AU2014205609A1 - Fracturing fluids including amine oxides as flowback aids - Google Patents
Fracturing fluids including amine oxides as flowback aids Download PDFInfo
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- AU2014205609A1 AU2014205609A1 AU2014205609A AU2014205609A AU2014205609A1 AU 2014205609 A1 AU2014205609 A1 AU 2014205609A1 AU 2014205609 A AU2014205609 A AU 2014205609A AU 2014205609 A AU2014205609 A AU 2014205609A AU 2014205609 A1 AU2014205609 A1 AU 2014205609A1
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- 239000012530 fluid Substances 0.000 title claims abstract description 83
- 150000001412 amines Chemical class 0.000 title claims abstract description 60
- LFQSCWFLJHTTHZ-UHFFFAOYSA-N Ethanol Chemical compound CCO LFQSCWFLJHTTHZ-UHFFFAOYSA-N 0.000 claims description 40
- 230000015572 biosynthetic process Effects 0.000 claims description 28
- 238000000034 method Methods 0.000 claims description 22
- -1 dodecyl- Chemical group 0.000 claims description 19
- 125000004432 carbon atom Chemical group C* 0.000 claims description 14
- 125000000217 alkyl group Chemical group 0.000 claims description 13
- 239000000654 additive Substances 0.000 claims description 10
- 230000000996 additive effect Effects 0.000 claims description 10
- 239000003795 chemical substances by application Substances 0.000 claims description 9
- GATZCJINVHTSTO-UHFFFAOYSA-N didecylmethylamine oxide Chemical group CCCCCCCCCC[N+](C)([O-])CCCCCCCCCC GATZCJINVHTSTO-UHFFFAOYSA-N 0.000 claims description 8
- 239000004094 surface-active agent Substances 0.000 claims description 6
- PLLBRTOLHQQAQQ-UHFFFAOYSA-N 8-methylnonan-1-ol Chemical group CC(C)CCCCCCCO PLLBRTOLHQQAQQ-UHFFFAOYSA-N 0.000 claims description 5
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 claims description 4
- 208000005156 Dehydration Diseases 0.000 claims description 3
- 238000005260 corrosion Methods 0.000 claims description 3
- 230000007797 corrosion Effects 0.000 claims description 3
- 239000003112 inhibitor Substances 0.000 claims description 3
- 239000004971 Cross linker Substances 0.000 claims description 2
- 239000002253 acid Substances 0.000 claims description 2
- 239000012190 activator Substances 0.000 claims description 2
- 239000002518 antifoaming agent Substances 0.000 claims description 2
- 230000003115 biocidal effect Effects 0.000 claims description 2
- 239000003139 biocide Substances 0.000 claims description 2
- 239000002738 chelating agent Substances 0.000 claims description 2
- 239000003638 chemical reducing agent Substances 0.000 claims description 2
- 239000004927 clay Substances 0.000 claims description 2
- 229910052742 iron Inorganic materials 0.000 claims description 2
- 239000003002 pH adjusting agent Substances 0.000 claims description 2
- 239000002455 scale inhibitor Substances 0.000 claims description 2
- 239000003381 stabilizer Substances 0.000 claims description 2
- 239000000203 mixture Substances 0.000 description 52
- 238000009472 formulation Methods 0.000 description 42
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 21
- 238000012360 testing method Methods 0.000 description 12
- 238000005259 measurement Methods 0.000 description 11
- NLXLAEXVIDQMFP-UHFFFAOYSA-N Ammonia chloride Chemical compound [NH4+].[Cl-] NLXLAEXVIDQMFP-UHFFFAOYSA-N 0.000 description 7
- 125000000118 dimethyl group Chemical group [H]C([H])([H])* 0.000 description 6
- 238000006065 biodegradation reaction Methods 0.000 description 5
- 239000011148 porous material Substances 0.000 description 4
- 239000000126 substance Substances 0.000 description 4
- 150000001298 alcohols Chemical class 0.000 description 3
- ZRKZFNZPJKEWPC-UHFFFAOYSA-N decylamine-N,N-dimethyl-N-oxide Chemical compound CCCCCCCCCC[N+](C)(C)[O-] ZRKZFNZPJKEWPC-UHFFFAOYSA-N 0.000 description 3
- 239000007789 gas Substances 0.000 description 3
- 229930195733 hydrocarbon Natural products 0.000 description 3
- 150000002430 hydrocarbons Chemical class 0.000 description 3
- 239000000463 material Substances 0.000 description 3
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 2
- 230000000052 comparative effect Effects 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- YWWNNLPSZSEZNZ-UHFFFAOYSA-N n,n-dimethyldecan-1-amine Chemical compound CCCCCCCCCCN(C)C YWWNNLPSZSEZNZ-UHFFFAOYSA-N 0.000 description 2
- 230000035699 permeability Effects 0.000 description 2
- PUAQLLVFLMYYJJ-UHFFFAOYSA-N 2-aminopropiophenone Chemical compound CC(N)C(=O)C1=CC=CC=C1 PUAQLLVFLMYYJJ-UHFFFAOYSA-N 0.000 description 1
- 208000030507 AIDS Diseases 0.000 description 1
- 239000004215 Carbon black (E152) Substances 0.000 description 1
- 229920006328 Styrofoam Polymers 0.000 description 1
- 238000009825 accumulation Methods 0.000 description 1
- 235000019270 ammonium chloride Nutrition 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- 231100000693 bioaccumulation Toxicity 0.000 description 1
- 238000007664 blowing Methods 0.000 description 1
- 230000015556 catabolic process Effects 0.000 description 1
- 230000002596 correlated effect Effects 0.000 description 1
- 230000000875 corresponding effect Effects 0.000 description 1
- 230000000254 damaging effect Effects 0.000 description 1
- 238000011161 development Methods 0.000 description 1
- 238000011156 evaluation Methods 0.000 description 1
- 239000011521 glass Substances 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 229910052739 hydrogen Inorganic materials 0.000 description 1
- 238000011065 in-situ storage Methods 0.000 description 1
- 238000004519 manufacturing process Methods 0.000 description 1
- 238000002156 mixing Methods 0.000 description 1
- 229910052757 nitrogen Inorganic materials 0.000 description 1
- 125000002347 octyl group Chemical group [H]C([*])([H])C([H])([H])C([H])([H])C([H])([H])C([H])([H])C([H])([H])C([H])([H])C([H])([H])[H] 0.000 description 1
- 150000003071 polychlorinated biphenyls Chemical class 0.000 description 1
- 150000003856 quaternary ammonium compounds Chemical class 0.000 description 1
- 239000011435 rock Substances 0.000 description 1
- 229920006395 saturated elastomer Polymers 0.000 description 1
- 238000010561 standard procedure Methods 0.000 description 1
- 238000007655 standard test method Methods 0.000 description 1
- 239000008261 styrofoam Substances 0.000 description 1
- 125000004417 unsaturated alkyl group Chemical group 0.000 description 1
Classifications
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/62—Compositions for forming crevices or fractures
- C09K8/66—Compositions based on water or polar solvents
- C09K8/68—Compositions based on water or polar solvents containing organic compounds
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/602—Compositions for stimulating production by acting on the underground formation containing surfactants
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
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- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Chemical & Material Sciences (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Organic Chemistry (AREA)
- Materials Engineering (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Geochemistry & Mineralogy (AREA)
- Agricultural Chemicals And Associated Chemicals (AREA)
- Detergent Compositions (AREA)
- Lubricants (AREA)
Abstract
An aqueous fracturing fluid comprises an environmentally friendly flowback aid. The flowback aid includes an amine oxide having the formula (CH
Description
WO 2014/110058 PCT/US2014/010564 FRACTURING FLUIDS INCLUDING AMINE OXIDES AS FLOWBACK AIDS Field of the Invention [0001] The invention relates generally to fracturing fluids that contain a flowback aid, and methods of fracturing a subterranean formation using fracturing fluids that contain a flowback aid. Background of the Related Art [0002] Hydraulic fracturing is a process that forms fractures in a subterranean formation using a pressurized fluid. The fracturing fluid is introduced into the subterranean formation through a wellbore that has been drilled into the formation, and then pressurized to fracture the formation. Among other components, the fracturing fluid will typically contain a proppant material that enters into the newly formed fractures and prevents those fractures from closing up. [0003] At the end of a hydraulic fracturing job, a large surface-area fracture will have been created and propped permanently open by the application of a proppant laden, pressurized, often aqueous, hydraulic fluid. The next step in the hydraulic fracturing job is to decrease the pressure applied to the aqueous hydraulic fluid to allow the fluid sitting in the near well-bore region of the target formation between the targeted hydrocarbons and the wellbore to flow back into the well and up to the surface for treatment and disposal or re-use later. [0004] The amount of fracturing fluid left behind in the formation will diminish to an irreducible fraction and then stop flowing back. This irreducible fraction of fracturing fluid left behind in the formation will subsequently impede the flow of hydrocarbon from the petroliferous formation into the very high permeability proppant pack. [0005] A flowback aid may be included in the fracturing fluid to reduce capillary pressure and water blocks, thereby improving the kinetics of the flowback and preventing or minimizing the leaving-behind of any substantial amount of the 1 WO 2014/110058 PCT/US2014/010564 fracturing fluid. Flowback aids, such as surfactants, have also been shown to aid in the "clean-up" of the proppant pack, thereby accelerating the flow of hydrocarbons through the high permeability proppant pack, as well. Known flowback aids each have their own set of properties and may present a tradeoff of one beneficial property for another undesirable property. Determining the best flowback aid for a specific reservoir may involve multiple considerations. [0006] Experience has demonstrated that a scientific measure of the ability of a flowback aid to change the wettability of the near wellbore formation or to reduce the water saturation in the pores of the targeted subterranean petroliferous formation can be obtained by accurately measuring the contact angle formed by the flowback aid within a capillary tube. In flowback tests on cores simulating the performance of an element of the reservoir under simulated in-situ conditions, experience has shown that capillary contact angles greater than 800 are correlated with the more efficient flowback of aqueous fluids (simulating those used in formation fracturing). Reducing the water saturation in the pores of the targeted subterranean petroliferous formation is desirable for increased production of oil or gas because the volume of the flow channel for oil or gas through the pores in the rock will be occupied, in part, by the immiscible water phase; and reducing the fraction of this volume that is occupied by water will necessarily increase the fraction of this volume that is available for flow by oil or gas. BRIEF SUMMARY [0007] One embodiment of the present invention provides an aqueous fracturing fluid, comprising an amine oxide of the formula (CH 3
)NO(R
1
)(R
2 ), where R 1 and R 2 are independently selected from linear or branched alkyl groups having from 8 to 16 carbon atoms. Another embodiment of the present invention provides an additive to a fracturing fluid, wherein the additive comprises an amine oxide of the formula
(CH
3
)NO(R
1
)(R
2 ), where R 1 and R 2 are independently selected from linear or branched alkyl groups having from 8 to 16 carbon atoms. [0008] Another embodiment of the present invention provides a method of fracturing a subterranean formation. The method comprises introducing a fracturing 2 WO 2014/110058 PCT/US2014/010564 fluid through a well bore into the subterranean formation, wherein the fracturing fluid comprises an amine oxide of the formula (CH 3
)NO(R
1
)(R
2 ), where R 1 and R 2 are independently selected from linear or branched alkyl groups having from 8 to 16 carbon atoms, pressurizing the fracturing fluid to fracture the subterranean formation, and allowing the fracturing fluid to flow back into the well bore from the subterranean formation. DETAILED DESCRIPTION [0009] One embodiment of the present invention provides an aqueous fracturing fluid, comprising an amine oxide of the formula (CH 3
)NO(R
1
)(R
2 ), where R 1 and R 2 are independently selected from linear or branched alkyl groups having from 8 to 16 carbon atoms. Another embodiment of the present invention provides an additive to a fracturing fluid, wherein the additive comprises an amine oxide of the formula
(CH
3
)NO(R
1
)(R
2 ), where R 1 and R 2 are independently selected from linear or branched alkyl groups having from 8 to 16 carbon atoms. A particularly preferred amine oxide is didecylmethyl amine oxide. Didecylmethyl amine oxide is an amine oxide of the formula (CH 3
)NO(R
1
)(R
2 ), in which R 1 is decyl- and R 2 is also decyl-. Other preferred amine oxides include those of the formula (CH 3
)NO(R
1
)(R
2 ), in which R 1 and R 2 are independently selected from linear or branched alkyl groups having from 8 to 12 carbon atoms. Specific examples of other particularly preferred amine oxides include those of the formula (CH 3
)NO(R
1
)(R
2 ), in which R 1 is octyl and R 2 is dodecyl-, those in which R 1 is nonyl- and R 2 is undecyl-, those in which R 1 is octyl- and R 2 is dimethyldecyl-, those in which R 1 is nonyl- and R 2 is methyldecyl-, those in which R 1 is dimethylhexyl- and R 2 is dodecyl-, those in which R 1 is methylheptyl- and R 2 is dodecyl-, those in which R 1 is dimethylhexyl and R 2 is dimethyldecyl-, those in which R 1 is methylheptyl- and R 2 is methyldecyl-, and mixtures of these with didecylmethyl amine oxide. [0010] The concentration of the amine oxide in the aqueous fracturing fluid may vary according to the requirements of a particular fracturing job. Preferably, the amine oxide is present in a concentration that is effective to improve the flowback of the fracturing fluid. In one embodiment, the amine oxide is present within the 3 WO 2014/110058 PCT/US2014/010564 fracturing fluid in a concentration between 0.00005 and 2.5 percent by weight. A more preferred amine oxide is with the concentration between 0.001 and 2.5 percent by weight; a yet more preferred amine oxide is with the concentration between 0.1 and 2.5 percent by weight; and an even yet more preferred amine oxide concentration is between 0.2 and 2.0 percent by weight of the fracturing fluid. [0011] In one embodiment of the invention, the aqueous fracturing fluid further includes a non-ionic co-surfactant such as an alcohol ethoxylate of the formula R 3 (OC 2
H
4 )x-OH, wherein R 3 is a linear or branched alkyl group having from 6 to 18 carbon atoms, and wherein x ranges from 3 to 25. One preferred alcohol ethoxylate is ethoxylated isodecylalcohol (also known as ethoxylated isodecanol). A more preferred range for x is from 6 to 18. A yet more preferred range for x is from 7 to 11. [0012] The concentration of alcohol ethoxylate in the fracturing fluid may vary according to the requirements of a particular fracturing job. Preferably, the alcohol ethoxylate is present in a concentration that is effective to improve the flowback of the fracturing fluid. In one embodiment, the alcohol ethoxylate is present in the fracturing fluid in a concentration between 5 and 15 percent by weight, preferably between 8 and 15 percent by weight and yet more preferably between 8 and 12 percent by weight of the fracturing fluid. Most preferably, it is the combination of alcohol ethoxylated and amine oxide that should be most effective to improve the flowback of the fracturing fluid. In an alternative, the combination of alcohol ethoxylated and amine oxide should be effective to cause the fracturing fluid to have a contact angle of greater than or equal to 80 degrees, and a surface tension less than about 24 mN/m. [0013] The aqueous fracturing fluid may include additional components that are known to those skilled in the art. For example, the aqueous fracturing fluid may include a proppant. Furthermore, the aqueous fracturing fluid may include one or more additive selected from an acid, a friction reducing agent, a viscosifying agent, a viscosifying agent activator or crosslinker, a biocide, a clay stabilizer, an anti foaming agent, a pH adjuster, a corrosion inhibitor, a fluid-loss additive, an iron 4 WO 2014/110058 PCT/US2014/010564 control agent, a scale inhibitor or scale control agent, a chelating agent, a viscosifying-agent breaker, and combinations thereof. [0014] Another embodiment of the present invention provides a method of fracturing a subterranean formation. The method comprises introducing a fracturing fluid through a well bore into the subterranean formation, wherein the fracturing fluid comprises an amine oxide of the formula (CH 3
)NO(R
1
)(R
2 ), where R 1 and R 2 are independently selected from linear or branched alkyl groups having from 8 to 16 carbon atoms, pressurizing the fracturing fluid to fracture the subterranean formation, and allowing the fracturing fluid to flow back into the well bore from the subterranean formation. It should be recognized that further embodiments of the method may include, for example, the use of a fracturing fluid in accordance with any of the fracturing fluid embodiments described herein. EXAMPLES EXAMPLE 1 - Biodegradation Testing [0015] Three flowback aid formulations were prepared for comparative testing using the Organisation for Economic Co-operation and Development (OECD, French: OCDE) method 301B. OECD 301B is a standard method for evaluating the biodegradation of a given chemical over time in an environment that simulates the break-down of that chemical in the real-world environment. If substances, such as polychlorinated biphenyls and Styrofoam cups degrade in the environment too slowly, they can exert a damaging effect on the environment simply by excessive accumulation, termed "bioaccumulation". Such substances are not considered to be "environmentally friendly" as a result of their low rate of biodegradation. Based on the results obtained from the OECD 301B protocol, tabulated in Table 1, it can be judged that Formulation C is the least degraded during the 28-day test and is therefore least "environmentally friendly" by this measure, while Formulation G performs preferably in the environment compared with Formulation C, and 5 WO 2014/110058 PCT/US2014/010564 Formulation A performs yet more preferably in the environment compared with Formulations C and G. Table 1 - Biodegradation Testing ID Sample / blend in water Biodegradation % (28 days) A 12% alcohol ethoxylate 100 (only) C 12% alcohol ethoxylate + 0.7% dimethyl dicoco quaternary 60 ammonium chloride G 12% alcohol ethoxylate + 1.5% didecylmethyl 78 amine oxide EXAMPLE 2 - Contact Angle Testing [0016] A number of flowback aid formulations were prepared for comparative testing. Some of the formulations contained a single flowback aid and other formulations contained a blend of flowback aids. Table 2, below, identifies ten different formulations A-J. The composition and concentration of each flowback aid(s) is identified in the second column. The identified flowback aid(s) in each formulation were added to water. For example, Formulation G contained 12% alcohol ethoxylate (ethoxylated isodecylalcohol, available as Serdox NDL 9,8 from Elementis Specialties, Inc., Hightstown, NJ), 1.5% amine oxide (didecylmethyl amine oxide), and 86.5% water. The quaternary ammonium compound ("Quat") used in Formulations C and D was a dimethyl dicoco quaternary ammonium chloride, where the coco group is either a saturated or unsaturated alkyl having from 12 to 16 carbon atoms (available as Corsaquat 2C-75 from CorsiTech of Houston, Texas). Formulation J uses a decyldimethyl amine oxide (a "single tail" amine 6 WO 2014/110058 PCT/US2014/010564 oxide) for comparison with the didecylmethyl amine oxide (a "double tail" amine oxide) used in Formulations E to I. [0017] Prior to testing, each of the identified formulations was further diluted with water to make a 0.2 weight percent (wt%) solution (containing 0.2 wt% of the formulation described in column 2 of Table 2). For example, a 0.2 wt% solution could be prepared by combining 0.2 grams of a flowback aid formulation of Table 2 with 99.8 g of water. It is the 0.2 wt% solution that is used in the contact angle measurements of Table 2 and the surface tension measurements of Table 3. All percentages mentioned in Tables 1, 2, and 3 are weight percentages. [0018] Contact angles were measured using capillary tubes. The method that was used to measure contact angles included measuring the relative contact angle of deionized (DI) water on a glass surface that has been treated (coated) with a surfactant solution. Specifically, the method included: (a) touching the surface of the 0.2% surfactant solution with a capillary tube and allowing the solution to rise into the capillary tube so that the solution will coat the walls of the tube for a few seconds, (b) draining the capillary tube by patting the capillary tube on a paper towel or slowly blowing dry nitrogen through the tube, and (c) touching the capillary tube to the surface of the DI water and recording any rise of the DI water into the capillary tube by measuring the height of the DI water in the capillary tube. [0019] The formula used to calculate the surface tension in the capillary tube is: T = r h d g / 2 cos(angle) where T is surface tension in a capillary tube (mN/m), r is the radius of the internal opening of the capillary tube (in m), h is the height that the DI water is raised to within the tube (in m), d is the density of the DI water (in kg/m 3 ), g is gravity (9.8 m/s2) and angle is the contact angle of the DI water against the sides of tube. The specification for contact angle is greater than or equal to 80 degrees. Table 2 - Contact Angle Measurements of a 0.2 wt% Solution 7 WO 2014/110058 PCT/US2014/010564 of Various Flowback Aid Formulations Average ID Sample/blend in Water Test Height (cm) Contact angle Contact Angle 1 1.6940 66.10 A 12% alcohol ethoxylate 2 1.7130 65.82 65.68 (only) 3 1.7600 65.11 1 0.3830 84.74 1.5% didecylmethyl B amine oxide 2 0.4010 84.50 84.52 (only) 3 0.4140 84.32 12% alcohol ethoxylate + 1 0.0500 89.31 C 0.7% dimethyl dicoco 2 0.0390 89.46 89.29 quaternary ammonium chloride 3 0.0660 89.09 12% alcohol ethoxylate + 1 0.0650 89.11 D 1.5% dimethyl dicoco 2 0.0460 89.37 89.31 quaternary ammonium chloride 3 0.0410 89.44 1 0.9550 76.80 12% alcohol ethoxylate + E 0.5% didecylmethyl 2 0.9050 77.50 77.34 amine oxide 3 0.8890 77.73 1 1.4380 69.89 12% alcohol ethoxylate + F 1.0% didecylmethyl 2 1.4420 69.83 70.15 amine oxide 3 1.3800 70.73 1 0.5110 82.98 12% alcohol ethoxylate + G 1.5% didecylmethyl 2 0.5530 82.40 82.25 amine oxide 3 0.6270 81.38 1 0.4910 83.26 12% alcohol ethoxylate + H 2.0% didecylmethyl 2 0.4040 84.45 83.62 amine oxide 3 0.4990 83.14 1 0.4460 83.88 12% alcohol ethoxylate + I 2.5% didecylmethyl 2 0.4520 83.79 83.79 amine oxide 3 0.4590 83.70 1 - 50.81 12% alcohol ethoxylate + J 1.5% decyldimethyl amine 2 - 55.20 51.68 oxide 3 - 49.03 [0020] According to the contact angle measurements in Table 2, Formulations A, E, F and J had an average contact angle less than 80 degrees and did not meet the specification. It would appear that all of the formulations except A, E, F, and J are somewhat acceptable; but formulations B, C, D, H, and I are more acceptable. 8 WO 2014/110058 PCT/US2014/010564 [0021] Formulation A establishes the performance of one relatively inexpensive and environmentally acceptable surfactant, an ethoxylated alcohol, at an average contact angle of 65.680. However, to achieve "acceptable" performance in flowback (as specified by those fracturing a subterranean formation), a flowback aid must exhibit a contact angle of at least 800 to obtain the necessary level of changing the wettability of the near wellbore formation or reducing the water saturation in the pores of the targeted subterranean petroliferous formation. [0022] Formulation B shows the performance of the amine oxide by itself. [0023] Formulations C and D blend in a little quaternary amine with the alcohol ethoxylate. While the 89+ degree contact angles are acceptable, the quaternary amine is not nearly so environmentally acceptable as either the ethoxylated alcohol or the amine oxide. [0024] Formulations E through I include 12 wt% alcohol ethoxylate with varying concentrations of the amine oxide (0.5%, 1.0%, 1.5%, 2.0% and 2.5%, respectively). Formulations G, H and I produced contact angles greater than 80 degrees. So, the data shows that good performance can be achieved by blending the amine oxide, either at 1.5 %, 2.0 %, or 2.5 %, into the relatively inexpensive ethoxylated alcohol. The resulting blend provides good performance in excess of the specification, while being environmentally friendly. [0025] Formulation J is a blend of 12 wt% alcohol ethoxylate and 1.5 wt% decyl dimethyl amine oxide in water. Accordingly, Formulation J is similar to Formulation G, with the only difference being that the "double tail" amine oxide (didecylmethyl amine oxide) of Formulation G has been replaced with the "single tail" amine oxide (decyldimethyl amine oxide) in Formulation J. The contact angle test showed that the average contact angle for Formulation G was 82.25 degrees, compared to the average contact angle for Formulation J of 51.68 degrees. This comparison shows that under otherwise identical conditions and concentrations, a double tail amine oxide yields surprisingly greater performance that a single tail amine oxide of similar composition. EXAMPLE 3 - Surface Tension Testing 9 WO 2014/110058 PCT/US2014/010564 [0026] The flowback aid Formulations A to J of Example 2 were also used in this Example 3, and surface tension measurements were made using 0.2 wt% solutions prepared in the same manner as described in Example 2. The methodology used to measure the surface tension data presented below in Table 3 is a variant of the ASTM Method D1331-89, entitled "Standard Test Methods for Surface and Interfacial Tension". The method used follows the methodology of D1331-89, except that a plate was used instead of a ring. The specification for surface tension is less than about 24 mN/m. Table 3 - Surface Tension Measurements of a 0.2 wt% Solution of Various Flowback Aid Formulations ID Sample/blend in Water Test Surface Tension Average (mN/m) Surface Tension (mN/m) 1 31.4510 A 12% alcohol ethoxylate 2 31.0264 31.11 (only) 3 30.8663 1 24.5719 1.5% didecylmethyl B amine oxide 2 24.4323 24.45 (only) 3 24.3497 12% alcohol ethoxylate + 1 31.0429 C 0.7% dimethyl dicoco 2 30.5915 30.72 quaternary ammonium chloride 3 30.5321 12% alcohol ethoxylate + 1 31.0834 D 1.5% dimethyl dicoco 2 30.7662 30.90 quaternary ammonium chloride 3 30.8585 1 24.1436 12% alcohol ethoxylate + E 0.5% didecylmethyl 2 23.9846 24.06 amine oxide 3 24.0581 1 24.3449 12% alcohol ethoxylate + F 1.0% didecylmethyl 2 24.2732 24.15 amine oxide 3 23.8321 1 24.2382 12% alcohol ethoxylate + G 1.5% didecylmethyl 2 23.8628 24.06 amine oxide 3 24.0771 1 24.1561 12% alcohol ethoxylate + H 2.0% didecylmethyl 2 24.1885 24.02 amine oxide 3 23.7242 10 WO 2014/110058 PCT/US2014/010564 1 24.1144 12% alcohol ethoxylate + I 2.5% didecylmethyl 2 23.9877 23.93 amine oxide 3 23.6842 1 39.73 12% alcohol ethoxylate + J 1.5% decyldimethyl amine 2 40.50 40.07 oxide 3 39.98 [0027] In comparing the results tabulated in Table 3 with the specification that the surface tension measurement be less than about 24 mN/m, it would appear that all of the formulations except A, C, D, and J are somewhat acceptable; but formulations E, F, G, H, and I are more acceptable; and formulation I is most acceptable. According to the contact angle measurements in Table 2, and the surface tension measurements in Table 3, it would appear that all of the formulations except and A, C, D, E, F, and J are somewhat acceptable; but formulations B, G, H, and I are more acceptable. By combining the performance evaluations with both the contact angle measurements (Table 2) and the surface tension measurements (Table 3), it would appear that formulations G, H, and I are yet more acceptable. [0028] The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used herein, the singular forms a "an" and "the" are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms "comprises" and/or "comprising," when used in this specification, specify the presence of stated features, integers, steps, operations, elements, components and/or groups, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof. The terms "preferably," "preferred," "prefer," "optionally," "may," and similar terms are used to indicate that an item, condition or step being referred to is an optional (not required) feature of the invention. [0029] The corresponding structures, materials, acts, and equivalents of all means or steps plus function elements in the claims below are intended to include any structure, material, or act for performing the function in combination with other claimed elements as specifically claimed. The description of the present invention 11 WO 2014/110058 PCT/US2014/010564 has been presented for purposes of illustration and description, but it is not intended to be exhaustive or limited to the invention in the form disclosed. Many modifications and variations will be apparent to those of ordinary skill in the art without departing from the scope and spirit of the invention. The embodiment was chosen and described in order to best explain the principles of the invention and the practical application, and to enable others of ordinary skill in the art to understand the invention for various embodiments with various modifications as are suited to the particular use contemplated. 12
Claims (28)
1. An aqueous fracturing fluid, comprising: an amine oxide of the formula (CH 3 )NO(R1)(R 2 ), where R 1 and R 2 are independently selected from linear or branched alkyl groups having from 8 to 16 carbon atoms.
2. The aqueous fracturing fluid of claim 1, wherein the concentration of the amine oxide in the fracturing fluid is between 0.00005 and 2.5 percent by weight.
3. The aqueous fracturing fluid of claim 2, wherein the amine oxide is didecyl methyl-amine oxide.
4. The aqueous fracturing fluid of claim 3, wherein the concentration of the amine oxide in the fracturing fluid is between 0.00005 and 2.5 percent by weight.
5. The aqueous fracturing fluid of claim 3, wherein the concentration of the amine oxide in the fracturing fluid is between 0.001 and 2.5 percent by weight.
6. The aqueous fracturing fluid of claim 3, wherein the concentration of the amine oxide in the fracturing fluid is between 0.1 and 2.0 percent by weight.
7. The aqueous fracturing fluid of claim 3, wherein the concentration of the amine oxide in the fracturing fluid is between 0.2 and 2.0 percent by weight.
8. The aqueous fracturing fluid of claim 2, wherein R 1 and R 2 are independently selected from linear or branched alkyl groups having from 8 to 12 carbon atoms. 13 WO 2014/110058 PCT/US2014/010564
9. The aqueous fracturing fluid of claim 2, wherein the amine oxide includes combinations of R 1 and R 2 selected from: R 1 is octyl- and R 2 is dodecyl-; R 1 is nonyl- and R 2 is undecyl-; R 1 is octyl- and R 2 is dimethyldecyl-; R 1 is nonyl- and R 2 is methyldecyl-; R 1 is dimethylhexyl- and R 2 is dodecyl-; R 1 is methylheptyl- and R 2 is dodecyl-; R 1 is dimethylhexyl- and R 2 is dimethyldecyl-; and R 1 is methylheptyl and R 2 is methyldecyl-.
10. The aqueous fracturing fluid of claim 2, further comprising a non-ionic co surfactant.
11. The aqueous fracturing fluid of claim 2, further comprising: an alcohol ethoxylate of the formula R 3 -(OC 2 H 4 )x-OH, wherein R 3 is a linear or branched alkyl group having from 6 to 18 carbon atoms, and wherein x ranges from 3 to 25.
12. The aqueous fracturing fluid of claim 11, wherein x ranges from 7 to 11.
13. The aqueous fracturing fluid of claim 11, wherein the concentration of alcohol ethoxylate in the fracturing fluid is between 0.0005 and 15 percent by weight.
14. The aqueous fracturing fluid of claim 11, wherein the concentration of alcohol ethoxylate in the fracturing fluid is between 0.0008 and 15 percent by weight.
15. The aqueous fracturing fluid of claim 11, wherein the concentration of alcohol ethoxylate in the fracturing fluid is between 0.0008 and 12 percent by weight.
16. The aqueous fracturing fluid of claim 11, wherein the alcohol ethoxylate is ethoxylated isodecylalcohol.
17. The aqueous fracturing fluid of claim 1, further comprising: a proppant. 14 WO 2014/110058 PCT/US2014/010564
18. The aqueous fracturing fluid of claim 1, further comprising: an additive selected from an acid, a friction reducing agent, a viscosifying agent, a viscosifying agent activator or crosslinker, a biocide, a clay stabilizer, an anti-foaming agent, a pH adjuster, a corrosion inhibitor, a fluid-loss additive, an iron control agent, a scale inhibitor or scale control agent, a chelating agent, a breaker, and combinations thereof.
19. A method of fracturing a subterranean formation, comprising: introducing a fracturing fluid through a well bore into the subterranean formation, wherein the fracturing fluid comprises an amine oxide of the formula (CH 3 )NO(R 1 )(R 2 ), where R 1 and R 2 are independently selected from linear or branched alkyl groups having from 8 to 16 carbon atoms; pressurizing the fracturing fluid to fracture the subterranean formation; and allowing the fracturing fluid to flow back into the well bore from the subterranean formation.
20. The method of claim 19, wherein the amine oxide concentration in the fracturing fluid is greater than 0.00005 percent by weight.
21. The method of claim 19, wherein the concentration of the amine oxide in the fracturing fluid is between 0.00005 and 2.5 percent by weight.
22. The method of claim 19, wherein the amine oxide is didecylmethyl amine oxide.
23. The method of claim 22, wherein the concentration of the amine oxide in the fracturing fluid is between 0.00005 and 2.5 percent by weight.
24. The method of claim 19, wherein the fracturing fluid further comprises an alcohol ethoxylate of the formula R 3 -(OC 2 H 4 )x-OH, wherein R 3 is a linear or 15 WO 2014/110058 PCT/US2014/010564 branched alkyl group having from 6 to 18 carbon atoms, and wherein x ranges from 3 to 25.
25. The aqueous fracturing fluid of claim 24, wherein the concentration of the alcohol ethoxylate concentration in the fracturing fluid is between 0.0005 and 15 percent by weight.
26. The aqueous fracturing fluid of claim 24, wherein the alcohol ethoxylate is ethoxylated isodecylalcohol.
27. The method of claim 19, wherein the fracturing fluid further comprises a proppant.
28. The method of claim 19, wherein the fracturing fluid further comprises an additive selected from a corrosion inhibitor, fluid-loss additive, and combinations thereof. 16
Applications Claiming Priority (3)
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| US13/739,172 | 2013-01-11 | ||
| US13/739,172 US10385260B2 (en) | 2012-01-12 | 2013-01-11 | Fracturing fluids including amine oxides as flowback aids |
| PCT/US2014/010564 WO2014110058A1 (en) | 2013-01-11 | 2014-01-07 | Fracturing fluids including amine oxides as flowback aids |
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| AU2014205609A1 true AU2014205609A1 (en) | 2015-06-04 |
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| US10815421B2 (en) * | 2013-03-15 | 2020-10-27 | Ethox Chemicals, Llc | Flow back aids |
| US9085958B2 (en) | 2013-09-19 | 2015-07-21 | Sas Institute Inc. | Control variable determination to maximize a drilling rate of penetration |
| US9163497B2 (en) | 2013-10-22 | 2015-10-20 | Sas Institute Inc. | Fluid flow back prediction |
| US9580996B2 (en) | 2014-05-27 | 2017-02-28 | General Electric Company | Modular assembly for processing a flowback composition stream and methods of processing the same |
| US11807811B2 (en) | 2015-02-20 | 2023-11-07 | Schlumberger Technology Corporation | Flowback aid for fracturing fluids |
| RU2715771C2 (en) | 2015-02-27 | 2020-03-03 | ЭКОЛАБ ЮЭсЭй ИНК. | Compositions for improving oil recovery |
| WO2017086919A1 (en) | 2015-11-16 | 2017-05-26 | Halliburton Energy Services, Inc. | Ethoxylated amines for use in subterranean formations |
| US10995262B2 (en) | 2015-11-16 | 2021-05-04 | Multi-Chem Group, Llc | Ethoxylated amines for use in subterranean formations |
| US11421149B2 (en) | 2015-11-16 | 2022-08-23 | Halliburton Energy Services, Inc. | Alkyl polyglycoside surfactants for use in subterranean formations |
| WO2017196938A1 (en) | 2016-05-13 | 2017-11-16 | Ecolab USA, Inc. | Corrosion inhibitor compositions and methods of using same |
| EP3475386B1 (en) | 2016-06-28 | 2021-03-31 | Ecolab USA Inc. | Composition, method and use for enhanced oil recovery |
| CN106167697B (en) * | 2016-06-30 | 2020-04-07 | 中国石油化工股份有限公司 | Oil-gas field fracturing cleanup composition, fracturing cleanup additive and preparation method thereof |
| US10351750B2 (en) * | 2017-02-03 | 2019-07-16 | Saudi Arabian Oil Company | Drilling fluid compositions with enhanced rheology and methods of using same |
| FR3066500B1 (en) | 2017-05-19 | 2019-06-21 | Rhodia Operations | ADDITIVES FOR THE REMOVAL OF FRACTURING FLUIDS USED FOR PETROLEUM EXTRACTION |
| MX2020005031A (en) | 2017-11-14 | 2020-08-17 | Stepan Co | Microemulsion flowback aids for oilfield uses. |
| WO2020101644A1 (en) | 2018-11-13 | 2020-05-22 | Halliburton Energy Sevices, Inc. | Methods and compositions for hydrocarbon recovery |
| US11499091B2 (en) | 2020-09-15 | 2022-11-15 | Cnpc Usa Corporation | Composition and method for improving the production of petroleum hydrocarbons |
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| US4970340A (en) * | 1985-07-01 | 1990-11-13 | Ethyl Corporation | Amine oxide process and composition |
| FI870365A (en) | 1986-11-14 | 1988-05-15 | Ecolab Inc | REFERENCE DETECTOR FOR EXHAUST OIL DETERGENTS IN MONTHO- (C1-4-ALKYL) -DI (C6-20-ALKYL) -AMINOXID FOERENING |
| US4938893A (en) | 1986-11-14 | 1990-07-03 | Ecolab Inc. | Detersive systems and low foaming aqueous surfactant solutions containing a mono (C1-4 alkyl)-di(C6-20 alkyl)-amine oxide compound |
| AU631887B2 (en) | 1989-06-12 | 1992-12-10 | Shiseido Company Ltd. | Hair growth stimulant |
| US5922794A (en) * | 1997-03-26 | 1999-07-13 | General Electric Company | Compositions stabilized with tertiary amine oxides |
| US6302209B1 (en) * | 1997-09-10 | 2001-10-16 | Bj Services Company | Surfactant compositions and uses therefor |
| US6719053B2 (en) * | 2001-04-30 | 2004-04-13 | Bj Services Company | Ester/monoester copolymer compositions and methods of preparing and using same |
| US6729408B2 (en) | 2002-04-05 | 2004-05-04 | Schlumberger Technology Corp. | Fracturing fluid and method of use |
| US20040209780A1 (en) * | 2003-04-18 | 2004-10-21 | Harris Phillip C. | Methods of treating subterranean formations using hydrophobically modified polymers and compositions of the same |
| US7655603B2 (en) * | 2005-05-13 | 2010-02-02 | Baker Hughes Incorported | Clean-up additive for viscoelastic surfactant based fluids |
| US7727935B2 (en) * | 2006-12-29 | 2010-06-01 | Halliburton Energy Services, Inc. | Dual-function additives for enhancing fluid loss control and stabilizing viscoelastic surfactant fluids |
| US7789160B2 (en) | 2007-10-31 | 2010-09-07 | Rhodia Inc. | Addition of nonionic surfactants to water soluble block copolymers to increase the stability of the copolymer in aqueous solutions containing salt and/or surfactants |
| US7987910B2 (en) * | 2007-11-07 | 2011-08-02 | Schlumberger Technology Corporation | Methods for manipulation of the flow of fluids in subterranean formations |
| US7893010B2 (en) * | 2008-05-08 | 2011-02-22 | Schlumberger Technology Corporation | Composition and method for fluid recovery from well |
| EP2300558A4 (en) * | 2008-06-02 | 2011-11-23 | Univ Texas | Methods of treating a hydrocarbon-bearing formation, a well bore, and particles |
| US7833943B2 (en) | 2008-09-26 | 2010-11-16 | Halliburton Energy Services Inc. | Microemulsifiers and methods of making and using same |
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| CN100591744C (en) * | 2009-01-20 | 2010-02-24 | 西南石油大学 | Oil gas well fracturing fluid for stratum of high temperature of 180-200 DEG C |
| CN101775276A (en) | 2010-02-02 | 2010-07-14 | 陕西科技大学 | Medium-temperature and high-temperature clean fracturing fluid and preparation method thereof |
| US7998911B1 (en) | 2010-03-02 | 2011-08-16 | Oil Chem Technologies | Environmental friendly fracturing and stimulation composition and method of using the same |
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| US20130180723A1 (en) | 2013-07-18 |
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| CA2892816A1 (en) | 2014-07-17 |
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